Colorimetric detection of shale inhibitors and/or salts

ABSTRACT

A method of detecting a shale inhibitor and/or a salt content in a wellbore servicing fluid (WSF), the method comprising determining a water salinity of a wellbore servicing fluid; dosing a known volume of the wellbore servicing fluid into a container; optionally adding a known volume of diluent (e.g., water) and mixing to provide a test sample; combining the test sample with a chromophore specific to the shale inhibitor and/or the salt, respectively, and optionally mixing; measuring the shale inhibitor content and/or the salt content, respectively, of the test sample using colorimetry; reporting the data from the measuring to a computer control system; determining a wellbore servicing fluid treatment based on the measured shale inhibitor content and/or salt content; subjecting the wellbore servicing fluid system to the treatment; and optionally waiting for a waiting time to retest the wellbore servicing fluid system and repeating.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority under 35 U.S.C. § 119(e) to U.S.Provisional Patent Application No. 62/992,619 filed on Mar. 20, 2020 andentitled “Colorimetric Detection of Shale Inhibitors and/or Salts,” thedisclosure of which is hereby incorporated herein by reference in itsentirety.

BACKGROUND

This disclosure relates to methods of servicing a wellbore. Morespecifically, it relates to methods of detecting shale inhibitors and/orsalts in wellbore servicing fluids.

Natural resources such as gas, oil, and water residing in a subterraneanformation or zone are usually recovered by drilling a wellbore down tothe subterranean formation while circulating a drilling fluid in thewellbore. After terminating the circulation of the drilling fluid, astring of pipe, e.g., casing, is run in the wellbore. The drilling fluidis then usually circulated downward through the interior of the pipe andupward through the annulus, which is located between the exterior of thepipe and the walls of the wellbore. Shale inhibitors and salts areubiquitous components in drilling fluids. Shale inhibitors and/or saltscan have predetermined concentrations in drilling fluids to preventproblems during the drilling process, such as viscosity build-up, bitballing, wellbore caving and ballooning, etc. However, during thedrilling process, shale inhibitors and/or salts can be lost to or gainedfrom the formation. The inability to accurately identify the activeconcentration of shale inhibitors and/or salts in drilling fluids inreal-time can result in economic losses (e.g., increased incidence ofnon-productive time). Thus, an ongoing need exists for real-timequantitative detection of shale inhibitors and/or salts in wellboreservicing fluids, such as drilling fluids.

The foregoing has outlined rather broadly the features and technicaladvantages of the present invention in order that the detaileddescription of the invention that follows may be better understood.Additional features and advantages of the invention will be describedhereinafter that form the subject of the claims of the invention. Itshould be appreciated by those skilled in the art that the conceptionand the specific embodiments disclosed may be readily utilized as abasis for modifying or designing other structures for carrying out thesame purposes of the present invention. It should also be realized bythose skilled in the art that such equivalent constructions do notdepart from the spirit and scope of the invention as set forth in theappended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present disclosure and theadvantages thereof, reference is now made to the following briefdescription, taken in connection with the accompanying drawings anddetailed description, wherein like reference numerals represent likeparts.

FIG. 1 is a flow chart showing a representative method for measuring asalt content in a wellbore servicing fluid according to this disclosure.

FIG. 2 is a flow chart showing a representative method for measuring ashale inhibitor content in a wellbore servicing fluid according to thisdisclosure.

DETAILED DESCRIPTION

It should be understood at the outset that although an illustrativeimplementation of one or more embodiments are provided below, thedisclosed systems and/or methods may be implemented using any number oftechniques, whether currently known or in existence. The disclosureshould in no way be limited to the illustrative implementations,drawings, and techniques below, including the exemplary designs andimplementations illustrated and described herein, but may be modifiedwithin the scope of the appended claims along with their full scope ofequivalents.

Disclosed herein are methods of detecting shale inhibitors and/or saltsin wellbore servicing fluids or compositions (collectively referred toherein as WSFs). The amount (e.g., concentration) of shale inhibitorsand/or salts can be determined by reacting the shale inhibitors and/orsalts with a detector compound, which may result in highly conjugatedmolecules that display color (e.g., visual color); wherein such highlyconjugated molecules can absorb light in the ultraviolet-visible(UV-VIS) range and/or in the visible (VIS) range; and wherein theabsorption intensity can be used to derive the amount of the shaleinhibitors and/or salts in the WSF. Although described hereinbelow withreference to absorbance, in aspects light reflectance can be utilized.

In an aspect, a method of detecting a shale inhibitor and/or a salt in aWSF can include (a) contacting an aliquot of the WSF with a detectorcompound to form a detection solution; wherein the WSF includes theshale inhibitor and/or the salt; and wherein the detection solution ischaracterized by at least one absorption peak wavelength in the range offrom about 380 nanometers (nm) to about 760 nm; (b) detecting anabsorption intensity for the detection solution at a wavelength withinabout ±20% of the at least one absorption peak wavelength; (c) comparingthe absorption intensity of the detection solution at the wavelengthwithin about ±20% of the at least one absorption peak wavelength with atarget absorption intensity of the shale inhibitor and/or the salt todetermine the amount of the shale inhibitor and/or the salt in the WSF;and (d) comparing the amount of the shale inhibitor and/or salt in theWSF with a target amount of the shale inhibitor and/or the salt. Thedetection solution can be characterized by a visible color. In someaspects, the aliquot of the WSF can be further characterized by avisible color, wherein the visible color and/or color intensity of thedetection solution is different from the visible color and/or colorintensity of the aliquot of the WSF. In other aspects, the aliquot ofthe WSF can be colorless, for example the aliquot of the WSF can be aclear liquid.

Further disclosed herein are methods of servicing a wellbore in asubterranean formation including the real-time detection of shaleinhibitors and/or salts in WSF used in the wellbore and/or subterraneanformation.

In an aspect, a method of servicing a wellbore in a subterraneanformation can include preparing a WSF including a base fluid and a shaleinhibitor and/or salt, wherein the shale inhibitor and/or salt ispresent in the WSF in a target amount. The target amount can be greaterthan or equal to zero. For example, the target amount of the salt may bezero, in aspects.

In an aspect, the WSF suitable for use in the present disclosure mayinclude any suitable WSF. As used herein, a “servicing fluid” or“treatment fluid” refers generally to any fluid that may be used in asubterranean application in conjunction with a desired function and/orfor a desired purpose, including but not limited to fluids used todrill, complete, work over, fracture, repair, clean, or in any wayprepare a wellbore for the recovery of materials residing in asubterranean formation penetrated by the wellbore. The servicing fluidis for use in a wellbore that penetrates a subterranean formation. It isto be understood that “subterranean formation” encompasses both areasbelow exposed earth and areas below earth covered by water such as oceanor fresh water. In an aspect, the WSF (e.g., including a base fluid, ashale inhibitor and/or a salt) as disclosed herein can be a drillingfluid or a completion fluid. In an aspect, the WSF as disclosed hereincan be a drilling fluid.

In an aspect, the WSF includes a base fluid. In some aspects, the basefluid is an aqueous fluid. In other aspects, the base fluid includes anemulsion.

The salt detected via this disclosure can have monovalent and/orpolyvalent cations, alkali and alkaline earth metals, or combinationsthereof. Additional examples of suitable salts include NaCl, KCl, NaBr,CaCl₂, CaBr₂, MgCl₂, MgBr₂, ZnBr₂, acetate salts, sodium acetate,potassium acetate, ammonium chloride (NH₄Cl), potassium phosphate,sodium formate, potassium formate, cesium formate, or combinationsthereof. In an aspect, the WSF (e.g., the base fluid of the WSF)includes a brine including the salt to be detected.

In an aspect, the base fluid includes an aqueous fluid. Aqueous fluidsthat may be used in the WSF include any aqueous fluid suitable for usein subterranean applications, provided that the aqueous fluid iscompatible with the other components (e.g., shale inhibitor) used in theWSF. For example, the aqueous fluid may include water or a brine. In anaspect, the aqueous fluid includes an aqueous brine. In an aspect, theWSF suitable for use in the present disclosure may include any suitablesalt(s). In such aspect, the aqueous brine generally includes water andan inorganic monovalent salt, an inorganic multivalent salt, or both.The aqueous brine may be naturally occurring or artificially-created.Water present in the brine may be from any suitable source, examples ofwhich include, but are not limited to, sea water, tap water, freshwater,water that is potable or non-potable, untreated water, partially treatedwater, treated water, produced water, city water, well-water, surfacewater, liquids including water-miscible organic compounds, andcombinations thereof. The salt or salts in the water may be present inan amount ranging from greater than about 0% by weight to a saturatedsalt solution, alternatively from about 1 wt. % to about 30 wt. %, oralternatively from about 5 wt. % to about 10 wt. %, based on the weightof the salt solution. In an aspect, the salt or salts in the water maybe present within the base fluid in an amount sufficient to yield asaturated brine. As will be appreciated by one of skill in the art, andwith the help of this disclosure, the type and concentration of saltsolutions utilized as a base fluid is dependent on the WSF density(e.g., drilling fluid density, completion fluid density, etc.), whichmay range from about 8 lb/gallon to about 20 lb/gallon, alternativelyfrom about 10 lb/gallon to about 18 lb/gallon, or alternatively fromabout 12 lb/gallon to about 16 lb/gallon.

Nonlimiting examples of aqueous brines suitable for use in the presentdisclosure include chloride-based, bromide-based, phosphate-based orformate-based brines containing monovalent and/or polyvalent cations,salts of alkali and alkaline earth metals, or combinations thereof.Additional examples of suitable brines include, but are not limited tobrines including salts such as NaCl, KCl, NaBr, CaCl₂, CaBr₂, MgCl₂,MgBr₂, ZnBr₂, acetate salts, sodium acetate, potassium acetate, ammoniumchloride (NH₄Cl), potassium phosphate, sodium formate, potassiumformate, cesium formate, or combinations thereof. In an aspect, the basefluid includes a brine.

In an aspect, the base fluid includes an emulsion. In such aspect, theemulsion is an oil-in-water emulsion including a non-oleaginous (e.g.,an aqueous fluid of the type previously described herein) continuousphase and an oleaginous (e.g., an oil-based fluid, such as for examplean oleaginous fluid) discontinuous phase. Oleaginous fluids that may beused in the WSF include any oleaginous fluid suitable for use insubterranean applications, provided that the oleaginous fluid iscompatible with the shale inhibitor and/or salt used in the WSF.Examples of oleaginous fluids suitable for use in a WSF include, but arenot limited to, petroleum oils, natural oils, synthetically-derivedoils, oxygenated fluids, or combinations thereof. In an aspect, theoleaginous fluid includes diesel oil, kerosene oil, mineral oil,synthetic oils, aliphatic hydrocarbons, polyolefins (e.g., alphaolefins, linear alpha olefins and/or internal olefins), paraffins,silicone fluids, polydiorganosiloxanes, oxygenated solvents, esters,diesters of carbonic acid, alcohols, alcohol esters, ethers, ethyleneglycol, ethylene glycol monoalkyl ether, ethylene glycol dialkyl ether,or combinations thereof, wherein the alkyl groups are methyl, ethyl,propyl, butyl, and the like.

The base fluid may be present within the WSF in any suitable amount. Forexample, the base fluid may be present within the WSF in an amount offrom about 10 wt. % to about 99 wt. %, alternatively from about 20 wt. %to about 95 wt. %, or alternatively from about 40 wt. % to about 90 wt.%, based on the total weight of the WSF. Alternatively, the base fluidmay include the balance of the WSF after considering the amount of theother components used. As will be appreciated by one of skill in theart, and with the help of this disclosure, the amount of base fluid(e.g., aqueous base fluid) in the WSF depends on the desired density ofthe WSF.

In an aspect, the WSF suitable for use in the present disclosure mayinclude any suitable shale inhibitor.

Shale is a clay-rich sedimentary rock, wherein the shale includes atleast about 5 wt. % clay material, based on the total weight of theshale. When shale is exposed to water (e.g., an aqueous fluid; anaqueous-base fluid; a water-containing fluid, such as an emulsion;etc.), the clay in the shale can adsorb water and swell, therebyresulting in potential problems during drilling and/or completionprocesses, such as viscosity build-up, bit balling, wellbore caving,wellbore ballooning, subterranean formation integrity loss, collapse ofsubterranean formation, etc.

Generally, a shale inhibitor refers to a chemical compound having theability to inhibit water-reactive formations (e.g., water-reactivesubterranean formations; subterranean formations having water-reactiveminerals) from collapsing or losing integrity when the formations comein contact with a water-containing fluid (e.g., an aqueous fluid; anaqueous-base fluid; a water-containing fluid, such as an emulsion;etc.); for example by limiting water uptake by such formations. Forpurposes of the disclosure herein, the term “water-reactive” refers toformations (e.g., subterranean formations) and/or minerals thereof thatcan absorb water, uptake water, react with water, and the like, orcombinations thereof. Water-reactive formations can encompass anysubterranean formations containing clay or clay-based materials, such asshale. For purposes of the disclosure herein, the terms “shaleinhibitor” and “clay inhibitor” can be used interchangeably and refer tochemical compounds having the ability to inhibit water uptake byclay-containing subterranean formations (i.e., water-reactivesubterranean formations). Without wishing to be limited by theory, claycontains hydrous aluminum silicates having hydroxyl ions that arecapable of forming hydrogen bonds. Further, without wishing to belimited by theory, shale inhibitors are chemical compounds havingfunctional groups (e.g., amine functional groups, protonated aminefunctional groups) that can form hydrogen bonds with the clay (i.e.,with the water and/or hydroxyl groups present in the clay), therebyinhibiting water adsorption by the clay material, for example byblocking sites available for hydrogen bonding and rendering such sitesunavailable for hydrogen bonding with water molecules. Furthermore, andwithout wishing to be limited by theory, the shale inhibitor mayinteract with the subterranean formation via a variety of physicalbonds, such as hydrogen bonds, electrostatic interactions, van der Waalsinteractions, ionic interactions, dipole-dipole interactions, and thelike, or combinations thereof.

In an aspect, the shale inhibitor can include a salt (e.g., potassiumchloride (KCl), sodium chloride (NaCl)), a polymer (e.g., a highmolecular weight polymer (e.g., a polyacrylamide)), a charged polymer,or a combination thereof. For example, the shale inhibitor can includean amine functional group, (e.g., a primary amine functional group, asecondary amine functional group, a tertiary amine functional group, orcombinations thereof) and/or a protonated amine functional group (e.g.,a protonated primary amine functional group, a protonated secondaryamine functional group, a protonated tertiary amine functional group, orcombinations thereof). Without wishing to be limited by theory, aminefunctional groups and/or protonated amine functional groups in theamine-based shale inhibitor can form hydrogen bonds with the clay (i.e.,with the water and/or hydroxyl groups present in the clay), therebyinhibiting water adsorption by the clay material, for example byblocking sites available for hydrogen bonding and rendering such sitesunavailable for hydrogen bonding with water molecules. Further, withoutwishing to be limited by theory, the shale inhibitor may minimize shaleor clay hydration and thus prevent or reduce the adsorption of water bydownhole water-reactive formations to prevent or reduce a loss ofwellbore and/or subterranean formation stability. In embodiments, theshale inhibitor is not an amine-based shale inhibitor.

In an aspect, a shale inhibitor may be included within the WSF in asuitable or effective amount (e.g., an amount effective to providedesired shale inhibitory properties to the WSF). The resultant amount ofshale inhibitor that is necessary to impart desired shale inhibitoryproperties to a WSF may be dependent upon a variety of factors such asthe composition of the WSF; the presence or absence of various additivesin the WSF; the intended formation location where the WSF is expected tobe used to inhibit water uptake; the composition of the formation; thepressure of the formation; the temperature of the formation; thediameter of the hole; and the like; or combinations thereof.

In an aspect, a shale inhibitor may be present within the WSF in anamount (e.g., target amount) of from about 0.01 wt. % to about 5 wt. %,alternatively from about 0.02 wt. % to about 4 wt. %, or alternativelyfrom about 0.03 wt. % to about 3 wt. %, based on the total weight of theWSF. For purposes of the disclosure herein, the target amount of shaleinhibitor in the WSF refers to the desired amount of shale inhibitor inthe WSF; e.g., the amount of shale inhibitor effective to providedesired shale inhibitory properties to the WSF.

The WSF may further include additional additives as deemed appropriatefor improving the properties of the fluid. Such additives may varydepending on the intended use of the fluid in the wellbore. Examples ofsuch additives include, but are not limited to suspending agents,density reducing additives, settling prevention agents, expansionadditives, clays, salts, accelerants, set retarders, lignosulfonates,defoamers, surfactants, dispersing agents, fluid loss control agents,weighting materials, dispersants, fillers, zeolites, barite, calciumsulfate, silica flour, sand, slag, vitrified shale, fly ash, pozzolanicash, lime, formation conditioning agents, fluid absorbing materials,resins, aqueous superabsorbers, viscosifying agents, gelling agents,crosslinkers, mechanical property modifying additives, elastomers,styrene-butadiene copolymers, conventional reinforcing materials, carbonfibers, glass fibers, metal fibers, minerals fibers, and the like, orcombinations thereof. These additives may be introduced singularly or incombination using any suitable methodology and in amounts effective toproduce the desired improvements in the properties of the WSF. As willbe appreciated by one of skill in the art with the help of thisdisclosure, any of the components and/or additives used in the WSFshould be compatible with the shale inhibitor used in the WSFcomposition.

In an aspect, the WSF as disclosed herein may be prepared by using anysuitable method or process. The components of the WSF (e.g., shaleinhibitor, base fluid, additives, etc.) may be combined and mixed in byusing any mixing device compatible with the composition, e.g., a mixer,a batch mixer, a batch mixer with impellers and/or paddles, a blender, abatch blender, single ribbon type blenders, double ribbon type blenders,horizontal blenders, vertical blenders, inclined blenders, single ordouble ribbon type blenders which could further be horizontal, verticalor inclined, mixing eductors, dry powder eductors, dry powder eductorwith centrifugal pump followed by circulation loop, cyclone-type dry toliquid mixer, inline static mixers, and the like, or any suitablecombination thereof.

In an aspect, the components of the WSF are combined at the well site;alternatively, the components of the WSF are combined off-site and aretransported to and used at the well site. The resulting WSF may bepumped downhole where it may function as intended (e.g., prevent and/orreduce water uptake by water-reactive formations).

As will be appreciated by one of skill in the art, and with the help ofthis disclosure, a WSF including a shale inhibitor and/or salt asdisclosed herein may be used for preventing and/or reducing water uptakeby water-reactive formations in any suitable stage of a wellbore's life,such as for example, during a drilling operation, completion operation,etc.

In an aspect, a method of servicing a wellbore in a subterraneanformation can include detecting a shale inhibitor and/or salt in a WSF(e.g., testing the WSF for the presence and/or amount of shale inhibitorand/or salt in the WSF).

In some aspects, the shale inhibitor and/or salt may be detected in aWSF prior to using the WSF in a wellbore servicing operation (e.g., afirst amount or concentration that is determined prior to placing theWSF in the wellbore and/or subterranean formation, prior to circulatingthe WSF in the wellbore and/or subterranean formation); as will bediscussed in more detail later herein. In such aspects, the shaleinhibitor and/or salt may be detected in a WSF at any suitable timebetween preparing the WSF and placing the WSF in the wellbore and/orsubterranean formation. In such aspects, the WSF can be placed in thewellbore and/or subterranean formation subsequent to determining theamount of shale inhibitor and/or salt in the WSF (e.g., post-testing ofthe WSF for the presence and/or amount of shale inhibitor and/or salt inthe WSF). In aspects, prior to using the WSF in a wellbore servicingoperation, the WSF does not include a shale inhibitor and/or a salt.

As will be appreciated by one of skill in the art, and with the help ofthis disclosure, determining the concentration (e.g., a firstconcentration) of the shale inhibitor and/or salt in the WSF subsequentto adding a known amount (e.g., target amount) of shale inhibitor and/orsalt to the WSF (and prior to use thereof via placement in a wellbore)may provide validation of the detection method and/or may allow forcalibrating the detection method by reconciling the known amount (e.g.,target amount) of shale inhibitor and/or salt added to the WSF with thedetected amount. In aspects where the known amount (e.g., target amount)of shale inhibitor and/or salt added to the WSF and the detected amountare the same, no action is needed (e.g., no reconciliation isnecessary). In aspects where the known amount (e.g., target amount) ofshale inhibitor and/or salt added to the WSF and the detected amount aredifferent, a correction factor can be employed to reconcile (e.g.,correlate) the known amount (e.g., target amount) of shale inhibitorand/or salt added to the WSF with the detected amount. As will beappreciated by one of skill in the art, and with the help of thisdisclosure, the method of detecting the amount of shale inhibitor and/orsalt in the WSF might either overestimate or underestimate the actualamount (e.g., known amount, target amount) of shale inhibitor and/orsalt added to the WSF. For example, a correction factor could becalculated by dividing the detected (e.g., measured, calculated) amountof shale inhibitor and/or salt in the WSF by the actual amount (e.g.,known amount, target amount) of shale inhibitor and/or salt added to theWSF; or by dividing the actual amount (e.g., known amount, targetamount) of shale inhibitor and/or salt added to the WSF by the detected(e.g., measured, calculated) amount of shale inhibitor and/or salt inthe WSF. The correction factor (e.g., correlation factor) can be used tocorrelate the known amount (e.g., target amount) of shale inhibitorand/or salt added to the WSF with the detected amount. The correctionfactor (e.g., correlation factor) can be further used throughout testingof the WSF (e.g., subsequent to placing the WSF in a wellbore and/orsubterranean formation) to provide for a more accurate determination ofthe amount of shale inhibitor and/or salt in the WSF.

In other aspects, the shale inhibitor and/or salt may be detected in aWSF subsequent to using the WSF in a wellbore servicing operation (e.g.,a second amount or concentration that is determined subsequent toplacing the WSF in the wellbore and/or subterranean formation,subsequent to circulating the WSF in the wellbore and/or subterraneanformation); as will be discussed in more detail later herein. In suchaspects, the WSF may be placed in the wellbore and/or subterraneanformation pre-testing of the WSF for the presence and/or amount of shaleinhibitor and/or salt in the WSF. In aspects, only the first or thesecond amount or concentration of the shale inhibitor and/or the salt isdetermined. For example, in aspects determination of a concentration ofa salt is performed subsequent to using the WSF in a wellbore servicingoperation.

In an aspect, the WSF may be utilized in a drilling and completionoperation.

In an aspect, the WSF is a drilling fluid. A drilling fluid, also knownas a drilling mud or simply “mud,” is a fluid that is circulated througha wellbore to yield a circulated drilling fluid, while the wellbore isbeing drilled to facilitate the drilling operation. Generally, acirculated drilling fluid can carry cuttings up from downhole and arounda drill bit, transport them up an annulus, and allow their separation,followed by recycling the drilling fluid to the drilling operation.Further, a drilling fluid can cool and lubricate the drill bit, as wellas reduce friction between a drill string and the sides of the wellborehole. Furthermore, the drilling fluid aids in support of a drill pipeand drill bit, and provides a hydrostatic pressure necessary to maintainthe integrity of the wellbore walls and prevent well blowouts. The shaleinhibitor and/or salt in the drilling fluid may contact the subterraneanformation. When the subterranean formation includes clay and/or shale,at least a portion of the shale inhibitor and/or salt may interact withthe subterranean formation to prevent and/or reduce water uptake by suchwater-reactive formation (for example, and without wishing to be limitedby theory, by forming a physical bond such as a hydrogen bond with theclay), wherein at least a portion of the shale inhibitor and/or salt maybe retained by the subterranean formation, thereby depleting (e.g.,reducing the amount of) the shale inhibitor and/or salt in the drillingfluid. Salt may be incorporated into the drilling fluid from theformation during the drilling operation. Depending on the amount ofshale inhibitor and/or salt detected in the circulated drilling fluid,the amount of shale inhibitor and/or salt in the drilling fluid may beadjusted (e.g., increased or decreased) as necessary, as will bediscussed in more detail later herein.

In an aspect, the WSF (e.g., including the shale inhibitor and/or salt)is a completion fluid. In an aspect, when desired (for example, upon thecessation of drilling operations and/or upon reaching a desired depth),the wellbore or a portion thereof may be prepared for completion. In anaspect, the method of using a WSF (e.g., including shale inhibitorand/or salt, such as a completion fluid including an shale inhibitorand/or salt) may include completing the wellbore. Typically, completionfluids are free of solids. Generally, a completion fluid is placed inthe well to facilitate final operations prior to initiation ofproduction, such as setting screens, production liners, packers,downhole valves, etc. The wellbore, or a portion thereof, may becompleted by providing a casing string within the wellbore and cementingor otherwise securing the casing string within the wellbore. In such anaspect, the casing string may be positioned (e.g., lowered into) thewellbore to a desired depth prior to, concurrent with, or followingprovision of the completion fluid. The completion fluid may be displacedfrom the wellbore by pumping a flushing fluid, a spacer fluid, and/or asuitable cementitious slurry downward through an interior flowbore ofthe casing string and into an annular space formed by the casing stringand the wellbore walls. When the cementitious slurry has beenpositioned, the cementitious slurry may be allowed to set. The shaleinhibitor and/or salt in the completion fluid may contact thesubterranean formation whereby an amount of the shale inhibitor and/orsalt in the completion may increase or decrease. For example, when thesubterranean formation includes clay and/or shale, at least a portion ofthe shale inhibitor and/or salt may interact with the subterraneanformation to prevent and/or reduce water uptake by such water-reactiveformation (for example, and without wishing to be limited by theory, byforming a physical bond such as a hydrogen bond with the clay), whereinat least a portion of the shale inhibitor and/or salt may be retained bythe subterranean formation, thereby depleting (e.g., reducing the amountof) the shale inhibitor and/or salt in the completion fluid. Dependingon the amount of shale inhibitor and/or salt detected in the displacedcompletion fluid, the amount of shale inhibitor and/or salt introducedto the subterranean formation (for example via a flushing fluid, aspacer fluid, and/or a suitable cementitious slurry used to displace thecompletion fluid) may be adjusted as necessary, as will be discussed inmore detail later herein.

In an aspect, a method of detecting a shale inhibitor and/or salt in aWSF can include contacting an aliquot of the WSF with a detectorcompound to form a detection solution. For purposes of the disclosureherein, an aliquot of a liquid (e.g., WSF) refers to an amount of theliquid that is sufficient for allowing the detection of a shaleinhibitor and/or salt. For example, an aliquot of the WSF can be equalto or greater than about 0.001 milliliters (mL), alternatively equal toor greater than about 0.01 mL, alternatively equal to or greater thanabout 0.1 mL, alternatively equal to or greater than about 1 mL,alternatively equal to or greater than about 5 mL, alternatively equalto or greater than about 10 mL, or alternatively equal to or greaterthan about 25 mL.

In aspects where the WSF is substantially solids-free, an aliquot of theWSF can be contacted with the detector compound without any furtherprocessing. For purposes of the disclosure herein, a liquid isconsidered substantially solids-free when the amount of solids in theWSF does not interfere with the detection of the shale inhibitor and/orsalt. As will be appreciated by one of skill in the art, and with thehelp of this disclosure, whether solids present in the WSF interferewith the detection of the shale inhibitor and/or salt is dependent upona variety of factors, such as the amount of solids, the size and/or sizedistribution of solids, the light absorbing properties of the solids,the light diffraction properties of the solids, etc. For example, asubstantially solids-free WSF may include solids in an amount of lessthan about 1 wt. %, alternatively less than about 0.1 wt. %,alternatively less than about 0.01 wt. %, alternatively less than about0.001 wt. %, or alternatively less than about 0.0001 wt. %, based on thetotal weight of the WSF.

In aspects where the WSF includes solids (e.g., the WSF includes solidsthat may interfere with the detection of the shale inhibitor and/orsalt), at least a portion of the WSF may be subjected to a solidsremoval procedure to yield a substantially solids-free WSF. The solidsin the WSF can be debris, mud, WSF additives, drill cuttings, and thelike, or combinations thereof. In an aspect, the solids removalprocedure can be selected from the group that includes at leastfiltration, sedimentation, decantation, centrifugation, screening,chemical dissolution, and combinations thereof. For example, at least aportion of the WSF including an undesirable amount of solids (e.g.,solids that may interfere with the detection of the shale inhibitorand/or salt) may be filtered (e.g., via any suitable filter, such as asyringe filter) to yield a filtrate (passing through a filter) andsolids (retained onto a filter), wherein the filtrate is thesubstantially solids-free WSF and may be further subjected to shaleinhibitor and/or salt detection as disclosed herein. As another example,at least a portion of the WSF including an undesirable amount of solids(e.g., solids that may interfere with the detection of the shaleinhibitor and/or salt) may be contacted with a chemical compound thatmay convert the solids into soluble compounds (e.g., acid solubleparticles could be dissolved with an acid), thereby yielding thesubstantially solids-free WSF which may be further subjected to shaleinhibitor and/or salt detection as disclosed herein. An aliquot of thesubstantially solids-free WSF (e.g., an aliquot of the filtrate) can becontacted with a detector compound to form the detection solution.

In some aspects, the WSF may be subjected to more than one solidsremoval procedure to yield a substantially solids-free WSF. For example,a circulated drilling fluid may be subjected to centrifugation orscreening for the removal of cuttings, wherein the resulting WSF is notsolids-free and may be recycled to circulating in the wellbore and/orsubterranean formation; and wherein an aliquot of the resulting WSF maybe subjected to an additional solids removal procedure, such asfiltration, to yield an aliquot of the WSF that is substantiallysolids-free and may be further subjected to shale inhibitor and/or saltdetection as disclosed herein.

As will be appreciated by one of skill in the art, and with the help ofthis disclosure, the amount of WSF subjected to a solids removalprocedure to yield a substantially solids-free WSF can be greater thanthe aliquot of the substantially solids-free WSF contacted with adetector compound to form the detection solution, for example to allowfor more than one aliquot to be subjected to the detection method.Alternatively, the amount of WSF subjected to a solids removal procedureto yield a substantially solids-free WSF can be about the same as thealiquot of the substantially solids-free WSF contacted with a detectorcompound to form the detection solution.

In an aspect, the detector compound can include any suitable compoundthat can undergo a chemical reaction with the shale inhibitor and/or thesalt and produce a colored reaction product that has the ability toimpart a color and/or color intensity to the detection solution that isdifferent from the color and/or color intensity, respectively, of thealiquot of the WSF subjected to detection as disclosed herein. As willbe appreciated by one of skill in the art, and with the help of thisdisclosure, if the detector compound is colored, the color and/or colorintensity of the detection solution is different from the color and/orcolor intensity, respectively, of the detector compound. In an aspect,the detector compound is chromophore, for example a chromophore of thetype suitable for use with a detector such as Water Lens test kit asdescribed herein.

Nonlimiting examples of detector compounds suitable for use in thepresent disclosure include methylene blue, ninhydrin,indane-1,2,3-trione, hydrantin, quinhydrone, Dragendorff reagent,chloranil, N-halosuccinimide, N-bromosuccinimide, N-iodosuccinimide, ahydrazo compound, a diazonium salt, fluorescein, fluorescein halide,fluorescein chloride, and the like, or combinations thereof.

The detector compounds as disclosed herein, when combined with the shaleinhibitor and/or the salt, can undergo a chemical reaction with theshale inhibitor and/or the salt, respectively, and produce a coloredreaction product.

In an aspect, the detector compound can be contacted in any suitableamount with an aliquot of the WSF to yield the detection solution. Forexample, the detector compound can be contacted with an aliquot of theWSF in an amount of from about 0.01 mmol/liter to about 200 mmol/liter,alternatively from about 0.1 mmol/liter to about 150 mmol/liter,alternatively from about 1 mmol/liter to about 100 mmol/liter, oralternatively from about 1 mmol/liter to about 50 mmol/liter detectorcompound, based on the total volume of the detection solution.

Without wishing to be limited by theory, and as will be appreciated byone of skill in the art, and with the help of this disclosure, colorand/or color intensity can be detected by optical detection. Forpurposes of the disclosure herein, the term “optical detection” refersto detection performed visually by a human subject (e.g., an observationby an operator) and/or detection performed by a machine, for exampledetection with a spectrometer (e.g., ultraviolet-visible (UV-VIS)spectrometer and/or colorimeter) by using an analytical technique, suchas UV-VIS spectroscopy and/or colorimetry, respectively.

In aspects, the color and/or color intensity can be detected by ananalyzer, such as a Water Lens test kit available from Water Lens, LLCin Houston, Tex. Such a Water Lens test kit utilizes several independentdetection motifs in a 96-well plate format. Each 8-well strip (12 stripsto a plate) is filled with a different assay, each of which contains adetector compound such as a colorimetric dye (and optionally otherconstituents) sensitive to the presence of the component(s)/analyte(s)(e.g., the shale inhibitor(s) and/or the salt(s)) being measured. Theassays can then be freeze-dried, which can provide for a long shelflife, even in harsh environments, and rapid rehydration uponintroduction of the sample of wellbore servicing fluid. The tests can becarefully formulated to be compatible with specific analytes.

The analyzer (e.g., Water Lens test kit) can include a colorimeter thatoperates on the principle of colorimetric absorption by photosensitivedyes (e.g., one or more detector compounds such as dyes includingchromophores). When the dyes bind to respective analytes, thephotometric spectra of the dyes change. These changes can be read bymonitoring the absorbance of light at specific wavelengths as lightpasses through the sample(s). The absorbance characteristics can be readby a colorimeter, and the data generated can be used to calculate theconcentration of the particular analyte in each sample of the wellboreservicing fluid, for example via software.

Generally, color is associated specifically with electromagneticradiation (e.g., visible light) of a certain range of wavelengthsvisible to the human eye, for example electromagnetic radiation with awavelength between about 380 nanometers (nm) and about 760 nm (visiblespectrum). When all wavelengths of visible light are present, the lightappears “white” to a human. Colored materials (e.g., compounds, solids,liquids, solutions, gases) are colored because of the absorption ofvisible light (e.g., visible electromagnetic radiation). The color is aresult of the material absorbing a certain color of light, leading tothe visual perception of the compound being the complementary color. Ifany wavelength is removed (absorbed) from the visible light, a humanperceives the remaining combination of wavelengths of light as the“complementary” color. For example, when light passes through a liquid(e.g., colored solution), a characteristic portion of wavelengths can beabsorbed. If wavelengths of light from a certain region of the spectrumare absorbed by a material, then the materials will appear to be thecomplementary color to a human operator. For example, if violet lightwith wavelength of 400 nm is absorbed by a liquid, the liquid willvisually appear yellow. As another example, if blue light withwavelength of 450 nm is absorbed by a liquid, the liquid will visuallyappear orange. As yet another example, if green light with wavelength of530 nm is absorbed by a liquid, the liquid will visually appear purple.

In an aspect, the detection solution can be characterized by at leastone absorption peak wavelength in the range of from about 380 nm toabout 760 nm, alternatively from about 390 nm to about 750 nm,alternatively from about 400 nm to about 740 nm, alternatively fromabout 380 nm to about 460 nm, or alternatively from about 460 nm toabout 760 nm. In such aspect, the detection solution is characterized bya visible color (e.g., a color that can be visually perceived by a humanupon visual observation of the detection solution), thereby thedetection of the shale inhibitor and/or the salt can be performed viaoptical detection (e.g., visual detection and/or spectroscopicdetection). For purposes of the disclosure herein, the terms “absorptionpeak wavelength,” “maximum absorption wavelength,” and “wavelength ofmaximum absorbance” (λ_(max)) can be used interchangeably, and refer tothe wavelength where a specific compound or mixture of compoundsdisplays the highest absorbance (i.e., the highest absorption intensity)at a given concentration. As will be appreciated by one of skill in theart, and with the help of this disclosure, a specific compound ormixture of compounds can be characterized by a local maximum absorbanceand/or an absolute maximum absorbance, wherein the local maximumabsorbance refers to the maximum absorbance intensity in a givenwavelength range (e.g., the maximum absorbance intensity in a wavelengthrange of from about 500 nm to about 600 nm), and wherein the absolutemaximum absorbance refers to the maximum absorbance intensity across theentire investigated wavelength range (e.g., the maximum absorbanceintensity across the entire wavelength range of from about 380 nm toabout 760 nm). Further, and as will be appreciated by one of skill inthe art, and with the help of this disclosure, when a specific compoundor mixture of compounds displays a single absorption peak across theentire investigated wavelength range, the local maximum absorbance andthe absolute maximum absorbance are the same; and when a specificcompound or mixture of compounds displays two or more absorption peaksacross the entire investigated wavelength range, the peak with thehighest absorption intensity across the entire investigated wavelengthrange displays the absolute maximum absorbance, while the peaks otherthan the peak with the highest absorption intensity display localmaximum absorbances. Furthermore, and as will be appreciated by one ofskill in the art, and with the help of this disclosure, an absorptionpeak wavelength may correspond to a local maximum absorbance and/or anabsolute maximum absorbance. Absorption peak wavelengths arecharacteristic to each colored compound.

Generally, and without wishing to be limited by theory, colorimetry isan analytical technique (e.g., spectroscopic technique) that can be usedto determine the amount (e.g., concentration) of colored compounds insolutions by the application of the Beer-Lambert law, which states thatthe concentration of a solute is proportional to the absorbance (i.e.,absorption intensity). Typically, colorimetry uses the entire visiblespectrum (i.e., white light or visible light) or light with a specificwavelength, thereby allowing for the complementary color of the absorbedradiation to be observed as transmitted light. Colorimetry can use aparticular wavelength when the compound to be detected is known, andconsequently the wavelength at which such compound absorbs is known.Colorimetry does not scan the entire visible light spectrum (as opposedto UV-VIS spectroscopy). Further, colorimetry does not employ areference sample concurrently with a colored sample for detection.Colorimetry is performed with a colorimeter. A colorimeter may analyze asample in a laboratory setting. Alternatively, a portable colorimetermay be employed for sample analysis in the field (i.e., on location; inreal-time).

In an aspect, a method of detecting a shale inhibitor and/or a salt in aWSF can include detecting an absorption intensity for the detectionsolution at a wavelength within about ±20%, alternatively within about±10%, alternatively within about ±5%, alternatively within about ±1% ofthe at least one absorption peak wavelength (λ_(max)), or alternativelyat about the at least one absorption peak wavelength (λ_(max)).Generally, and without wishing to be limited by theory, across the lightspectrum wavelengths, colored compounds absorb radiation via peaks (asopposed to lines), owing to complex electronic transitions within themolecules of the colored compounds. Further, and without wishing to belimited by theory, the absorption intensity can be measured at anywavelength under the absorption peak; however, measuring the absorptionintensity at the at least one absorption peak wavelength (λ_(max)) willyield the greatest detection sensitivity (owing to the steepest slope ofa calibration curve relating absorption intensity to concentration).Furthermore, and without wishing to be limited by theory, the absorptionintensity is proportional to the amount (e.g., concentration) of coloredcompound (e.g., colored reaction product formed by the chemical reactionbetween the shale inhibitor and/or salt and the detector compound), inaccordance with the Beer-Lambert law. As will be appreciated by one ofskill in the art, and with the help of this disclosure, the further thewavelength at which the absorption intensity is measured is from the atleast one absorption peak wavelength (λ_(max)), the greater the error indetermining the amount (e.g., concentration) of colored compound (e.g.,colored reaction product formed by the chemical reaction between theshale inhibitor and/or salt and the detector compound).

In an aspect, detecting an absorption intensity for the detectionsolution at a wavelength within about ±20% of the at least oneabsorption peak wavelength (λ_(max)) can include visually detecting thecolor intensity of the detection solution. For example, a human (e.g.,an operator) can visually detect the color intensity of the solution,such as deep purple versus light purple, mildly deep red versusextremely deep red.

In an aspect, detecting an absorption intensity for the detectionsolution at a wavelength within about ±20% of the at least oneabsorption peak wavelength (λ_(max)) can include spectroscopicallydetecting an absorption intensity of the detection solution, for examplevia colorimetry and/or UV-VIS spectroscopy, as disclosed herein.

In an aspect, a method of detecting a shale inhibitor and/or salt in aWSF can further include heating the detection solution, e.g., heatingthe detection solution prior to detecting an absorption intensity forthe detection solution at a wavelength within about ±20% of the at leastone absorption peak wavelength. The detection solution can be heated byusing any suitable methodology (e.g., a heater, a heat exchanger, afired heater, a burner, a heating mantle, a heating element, etc.).

In an aspect, the detection mixture can be heated to a temperature offrom about 30° C. to about a boiling point of the detection solution,alternatively from about 30° C. to about 100° C., alternatively fromabout 35° C. to about 95° C., alternatively from about 40° C. to about90° C., or alternatively from about 50° C. to about 75° C. Withoutwishing to be limited by theory, heating the detection solution canspeed up (e.g., increase the rate of) the reaction between the detectorcompound and the shale inhibitor and/or the salt. As will be appreciatedby one of skill in the art, and with the help of this disclosure, andwithout wishing to be limited by theory, colored compounds absorbancegenerally varies with temperature, and consequently the heated detectionsolution can be cooled to ambient temperature (e.g., room temperature, atemperature of from about 15° C. to about 30° C.) prior to detecting anabsorption intensity for the detection solution at a wavelength withinabout ±20% of the at least one absorption peak wavelength. For example,the detection solution may be allowed to reach ambient temperature bylosing heat to the surrounding environment. As another example, thedetection solution can be cooled by using any suitable methodology(e.g., a cooler, a heat exchanger, a cooling bath, an ice bath, acooling element, etc.).

In an aspect, a method of detecting a shale inhibitor and/or salt in aWSF can include comparing the absorption intensity of the detectionsolution at the wavelength within about ±20% of the at least oneabsorption peak wavelength (λ_(max)) with a target absorption intensityof the shale inhibitor and/or the salt, respectively, to determine theamount of shale inhibitor and/or salt in the WSF.

In an aspect, comparing the absorption intensity of the detectionsolution at the wavelength within about ±20% of the at least oneabsorption peak wavelength (λ_(max)) with a target absorption intensityof the shale inhibitor and/or salt includes optically comparing thecolor and/or color intensity of the detection solution with a targetcolor and/or color intensity, respectively. For purposes of thedisclosure herein, the terms “optically comparing” and “opticalcomparison” refers to a comparison performed visually by a human subject(e.g., an operator) and/or a comparison performed by a machine, such asa computing device (e.g., computer, laptop, calculator, etc.) used inconjunction with (e.g., connected to, networked with, etc.) aspectrometer (e.g., UV-VIS spectrometer and/or colorimeter).

In an aspect, determining the amount of shale inhibitor and/or salt inthe WSF further includes visually comparing a visually observed colorand/or color intensity of the detection solution with a reference colorchart that correlates color and/or color intensity, respectively, withthe amount of the shale inhibitor and/or salt. In an aspect, a referencecolor chart can be constructed for each detector compound, given thateach detector compound might provide for a detection solution having adifferent color or a different color hue. For example, it is easier tovisually compare a red color to a reference color chart that employs thesame red color than it is to compare a red color to a reference colorchart that employs a red color having an orange hue. A reference colorchart can be constructed for a specific detector compound by preparingdetection solutions having known concentrations of the shale inhibitorand/or salt, and recording the color corresponding to eachconcentration, for example by taking a picture of the detectionsolution, and noting the concentration of the shale inhibitor and/orsalt that corresponds to the color and color intensity in the picture.The reference color chart can generally include two or more picturesrelating the color and color intensity of the detection solution tocorresponding known concentrations of the shale inhibitor and/or salt.As will be appreciated by one of skill in the art, and with the help ofthis disclosure, and without wishing to be limited by theory, the higherthe concentration of the shale inhibitor and/or salt, the more intense(e.g., deeper) the color of the detection solution; and the lower theconcentration of the shale inhibitor and/or salt, the less intense(e.g., paler) the color of the detection solution.

As will be appreciated by one of skill in the art, and with the help ofthis disclosure, when the color of the detection solution changes basedon the type of shale inhibitor and/or salt as well as the detectorcompound (e.g., some detector compounds may yield one color for shaleinhibitors including primary amines, and a different color for shaleinhibitors including secondary and/or tertiary amines), it may benecessary to create a reference color chart for a specific detectorcompound used in conjunction (e.g., paired) with a specific shaleinhibitor and/or salt. Further, and as will be appreciated by one ofskill in the art, and with the help of this disclosure, while as littleas two concentrations (e.g., a low concentration and a highconcentration) can be used for creating a reference color chart, usingmore than two, alternatively more than three, alternatively more thanfour, alternatively more than five, alternatively from three to abouttwenty, alternatively from about five to about fifteen, or alternativelyfrom about five to about ten concentrations for creating a referencecolor chart can significantly improve the accuracy of determining theamount of shale inhibitor and/or salt in the WSF.

In some aspects, visually comparing the color and/or color intensity ofthe detection solution with the reference color chart can includematching the color and/or color intensity of the detection solution withthe closest color and/or color intensity, respectively, on the referencecolor chart, wherein the closest color and/or color intensity determinesthe amount of the shale inhibitor and/or salt in the WSF. In otheraspects, visually comparing the color and/or color intensity of thedetection solution with the reference color chart can include matchingthe color and/or color intensity of the detection solution with theclosest two colors and/or color intensities, respectively, on thereference color chart, followed by estimating the amount of the shaleinhibitor and/or salt in the WSF between the amounts corresponding tothe closest two colors and/or color intensities, respectively.

In some aspects, the reference color chart can include images orpictures of detection solutions correlated with known concentrations ofthe shale inhibitor and/or salt printed on an appropriate substrate,such as paper (e.g., paper reference color chart), cardboard (e.g.,cardboard reference color chart), metal (e.g., metal reference colorchart), plastic (e.g., plastic reference color chart), and the like, orcombinations thereof. In other aspects, the reference color chartincluding images or pictures of detection solutions correlated withknown concentrations of the shale inhibitor and/or salt can be displayedon an electronic screen, such as a computer monitor, a laptop monitor, aphone screen, and the like, or combinations thereof.

In an aspect, comparing the absorption intensity of the detectionsolution at the wavelength within about ±20% of the at least oneabsorption peak wavelength (λ_(max)) with a target absorption intensityof the shale inhibitor and/or salt includes using a calibration curvethat correlates absorption intensity at the wavelength within about ±20%of the at least one absorption peak wavelength (λ_(max)) with the amountof the shale inhibitor and/or salt (e.g., known amount of the shaleinhibitor and/or salt).

In an aspect, a calibration curve can be constructed for each detectorcompound, given that each detector compound might provide for adetection solution having a different absorption peak wavelength(λ_(max)) (e.g., different color or a different color hue). Acalibration curve can be constructed for a specific detector compound bypreparing detection solutions having known concentrations of the shaleinhibitor and/or salt; subjecting the detection solutions tospectroscopy (e.g., UV-VIS spectroscopy and/or colorimetry); andplotting the known concentrations of the shale inhibitor and/or salt asa function of the corresponding measured absorption intensity. As willbe appreciated by one of skill in the art, and with the help of thisdisclosure, while the calibration curve can be constructed (e.g., drawn)with as little as two absorption intensity measurements corresponding totwo different known concentrations of the shale inhibitor and/or salt,at least three absorption intensity measurements corresponding to threedifferent known concentrations of the shale inhibitor and/or salt can beused for constructing the calibration curve, preferably as manyabsorption intensity measurements as it is deemed to be statisticallysignificant for any particular case (e.g., any particular detectorcompound, any particular pair of detector compound and shale inhibitorand/or salt).

Further, without wishing to be limited by theory, and as will beappreciated by one of skill in the art, and with the help of thisdisclosure, a calibration curve is generally accompanied by amathematical equation describing the calibration curve, and themathematical equation can be used as well for translating the absorptionintensity into the amount of shale inhibitor and/or salt in the WSF, forexample by entering into the equation the measured absorption intensityand calculating the corresponding amount of shale inhibitor and/or saltin the WSF.

Furthermore, as will be appreciated by one of skill in the art, and withthe help of this disclosure, sometimes spectrometers (e.g., colorimeter,portable colorimeter, UV-VIS spectrometer, portable UV-VIS spectrometer)can display a systematic error or bias, and as such it may be desired toconstruct the calibration curve with the same spectrometer that is usedfor measuring the absorption intensity.

In an aspect, a method of detecting a shale inhibitor and/or salt in aWSF can include comparing the amount of shale inhibitor and/or salt inthe WSF with a target amount of the shale inhibitor and/or salt.

In some aspects, the amount of shale inhibitor and/or salt in the WSFcan be about the same as the target amount of the shale inhibitor and/orsalt. In such aspects, the WSF can be placed in the wellbore and/orsubterranean formation where it may function as intended (e.g., preventand/or reduce water uptake by water-reactive formations).

In other aspects, the amount of shale inhibitor and/or salt in the WSFcan be different (e.g., less, lower, more, greater) than the targetamount of the shale inhibitor and/or salt. In such aspects, thedetermined amount of shale inhibitor and/or salt in the WSF can indicatea variance between the actual amount of the shale inhibitor and/or saltin the WSF and the desired or target amount of the shale inhibitorand/or salt. For example, such variance can range from greater thanabout 0% (e.g., wherein very little shale inhibitor and/or salt has beendepleted from or incorporated into the WSF, for example shale inhibitorand/or salt being lost to the formation or salt being incorporated fromthe formation) to about 100% (e.g., wherein substantially all of theshale inhibitor and/or salt has been depleted from the WSF, for exampleby being lost to the formation).

In an aspect, the amount of shale inhibitor and/or salt in the WSF canbe lower than the target amount of the shale inhibitor and/or the salt,respectively. For example, the amount of shale inhibitor and/or salt inthe WSF can be equal to or greater than about 1%, alternatively equal toor greater than about 5%, alternatively equal to or greater than about10%, alternatively equal to or greater than about 15%, alternativelyequal to or greater than about 20%, alternatively equal to or greaterthan about 25%, alternatively equal to or greater than about 30%,alternatively equal to or greater than about 35%, alternatively equal toor greater than about 40%, alternatively equal to or greater than about45%, alternatively equal to or greater than about 50%, alternativelyequal to or greater than about 55%, alternatively equal to or greaterthan about 60%, alternatively equal to or greater than about 65%,alternatively equal to or greater than about 70%, alternatively equal toor greater than about 75%, alternatively equal to or greater than about80%, alternatively equal to or greater than about 85%, alternativelyequal to or greater than about 90%, alternatively equal to or greaterthan about 95%, alternatively equal to or greater than about 99%, oralternatively about 100% lower than the target amount of the shaleinhibitor and/or salt. In some aspects, the amount of shale inhibitorand/or salt in the WSF can be greater than the target amount of theshale inhibitor and/or the salt, respectively. For example, during adrilling operation, the WSF may encounter different formation layersthat require different levels of inhibition (e.g., require differentconcentrations of shale inhibitor and/or salt), and as such the WSF mayhave an amount of shale inhibitor and/or salt that is greater than theamount required in a specific portion of the subterranean formation. Aswill be appreciated by one of skill in the art, and with the help ofthis disclosure, the amount of shale inhibitor and/or salt in the WSFmay be increased over time, for example as a result of encountering morereactive formations.

In some aspects, the amount of shale inhibitor and/or salt in the WSFcan be less than the target amount of the shale inhibitor and/or salt bya threshold amount. For purposes of the disclosure herein, the thresholdamount of shale inhibitor and/or salt is defined as the differencebetween the amount (e.g., actual amount, measured amount) of shaleinhibitor and/or salt in the WSF and the target amount of the shaleinhibitor and/or the salt, respectively. Further, for purposes of thedisclosure herein, the threshold amount of shale inhibitor and/or saltrefers to the amount of shale inhibitor and/or salt that is “missing”from the WSF (e.g., the amount of shale inhibitor and/or salt that hasbeen depleted from the WSF, for example by being lost to the formation)and which requires supplementation of shale inhibitor and/or salt intothe WSF, in order to provide for a WSF having the target amount of theshale inhibitor and/or the salt, respectively.

In aspects where the amount of shale inhibitor and/or salt in the WSF isless than the target amount of the shale inhibitor and/or the salt,respectively, by an amount that is equal to or greater than a thresholdamount, the WSF may require further processing prior to being used in awellbore servicing operation (e.g., supplemental shale inhibitor and/orsalt may be added to the WSF, in order to provide for a WSF having thetarget amount of the shale inhibitor and/or the salt, respectively).

As will be appreciated by one of skill in the art, and with the help ofthis disclosure, the threshold amount of shale inhibitor and/or saltthat dictates whether a WSF requires or does not require addition ofsupplemental shale inhibitor, salt, and/or base fluid, may depend on avariety of factors, such as the type of wellbore servicing operation,the composition of the WSF, the type and/or configuration of thewellbore, the type of subterranean formation, the subterranean formationconditions (e.g., temperature, pressure, etc.), and the like, orcombinations thereof.

The threshold amount of shale inhibitor and/or salt can be expressed asa percentage (%) of the target amount of the shale inhibitor and/or thesalt, respectively. For example, the threshold amount of shale inhibitorand/or salt can be equal to or greater than about 1%, alternativelyequal to or greater than about 5%, alternatively equal to or greaterthan about 10%, alternatively equal to or greater than about 15%,alternatively equal to or greater than about 20%, alternatively equal toor greater than about 25%, alternatively equal to or greater than about30%, alternatively equal to or greater than about 35%, alternativelyequal to or greater than about 40%, alternatively equal to or greaterthan about 45%, alternatively equal to or greater than about 50%,alternatively equal to or greater than about 55%, alternatively equal toor greater than about 60%, alternatively equal to or greater than about65%, alternatively equal to or greater than about 70%, alternativelyequal to or greater than about 75%, alternatively equal to or greaterthan about 80%, alternatively equal to or greater than about 85%,alternatively equal to or greater than about 90%, alternatively equal toor greater than about 95%, alternatively equal to or greater than about99%, or alternatively about 100% of the target amount of the shaleinhibitor and/or the salt, respectively.

In aspects where the amount of shale inhibitor and/or salt in the WSF isless than the target amount of the shale inhibitor and/or the salt,respectively, by an amount that is lower than the threshold amount, theWSF may be used in a wellbore servicing operation without furtherprocessing (e.g., without adding supplemental shale inhibitor and/orsalt to the WSF). For example, at least a portion of the WSF may beplaced in the wellbore and/or subterranean formation where it mayfunction as intended (e.g., prevent and/or reduce water uptake bywater-reactive formations).

In some aspects, the amount of shale inhibitor and/or salt in the WSFcan be greater than the target amount of the shale inhibitor and/or thesalt, respectively. In aspects where the amount of shale inhibitorand/or salt in the WSF is greater than the target amount of the shaleinhibitor and/or the salt, respectively, the WSF may be used in awellbore servicing operation without further processing (e.g., withoutadjusting the amount of shale inhibitor and/or salt in the WSF). As willbe appreciated by one of skill in the art, and with the help of thisdisclosure, the amount of shale inhibitor and/or salt in the WSF maybecome greater than the target amount of the shale inhibitor and/or saltowing to evaporation of water from the WSF, overtreatment of shaleinhibitor and/or salt in the WSF (e.g., adding excess shale inhibitorand/or salt to the WSF), influx of shale inhibitor and/or salt into theWSF, and the like, or combinations thereof.

In aspects where the amount of shale inhibitor and/or salt in the WSF iswithin about 1%, alternatively within about 5%, alternatively withinabout 10%, alternatively within about 15%, alternatively within about20%, or alternatively within about 25% of the target amount of the shaleinhibitor and/or the salt, respectively, the WSF may be used in awellbore servicing operation without further processing (e.g., withoutadding supplemental shale inhibitor, salt, base fluid, etc., to theWSF). As will be appreciated by one of skill in the art, and with thehelp of this disclosure, when the amount of shale inhibitor and/or saltin the WSF varies by a relatively small amount (e.g., less than about1%, alternatively less than about 5%, alternatively less than about 10%)from the target amount of the shale inhibitor and/or the salt,respectively, at least a portion of such variance can be owed toexperimental error factors, such as operator error, measuring errors,temperature variation, experimental noise, and the like, or combinationsthereof; and in such cases it may not be necessary to adjust the amountof shale inhibitor and/or salt in the WSF.

In an aspect, a method of servicing a wellbore in a subterraneanformation can include adjusting the amount of shale inhibitor and/orsalt in the WSF to provide for a WSF (e.g., an adjusted WSF, a correctedWSF, a supplemented WSF) having the target amount of the shale inhibitorand/or the salt, respectively.

In aspects where the amount of shale inhibitor and/or salt in the WSFvaries by equal to or greater than the threshold amount from the targetamount of the shale inhibitor and/or the salt, respectively, the WSF canbe adjusted (e.g., contacted with an effective supplemental amount ofshale inhibitor, salt, base fluid, etc.) to provide for the WSF havingthe target amount of the shale inhibitor and/or the salt, respectively.

In an aspect, the effective supplemental amount of can be determinedon-the-fly (e.g., in real-time); wherein the WSF having the targetamount of the shale inhibitor and/or the salt can be preparedon-location (e.g., on-site; at a wellbore site), by adding the effectivesupplemental amount of the shale inhibitor, the salt, the base fluid,etc., to the WSF. For purposes of the disclosure herein, the terms“on-the-fly” and “real-time” can be used interchangeably andcollectively refer to an action that is performed during an ongoingwellbore servicing operation; wherein performing such action can resultin changes to an ongoing wellbore servicing operation on a time scale ofless than about 30 minutes, alternatively less than about 15 minutes,alternatively less than about 10 minutes, alternatively less than about5 minutes, alternatively less than about 1 minute, alternatively lessthan about 30 seconds, alternatively less than about 15 seconds,alternatively less than about 10 seconds, alternatively less than about5 seconds, or alternatively less than about 1 second.

For purposes of the disclosure herein, the term “real-time” refers to anaction that is performed on a time scale that allows for feedback (e.g.,real-time feedback) to an ongoing wellbore servicing operation, whereinthe feedback affects the ongoing wellbore servicing operation. Forexample, real-time data, such as the measured (i.e., actual) amount ofshale inhibitor and/or salt in the WSF, can be provided about instantly(e.g., as soon as it is obtained) to a decision factor (e.g., anoperator, a computing device), wherein the decision factor can decide ordetermine whether it is necessary to add the supplemental amount (e.g.,of shale inhibitor, salt, base fluid, etc.) to the WSF or not, on a timescale (i.e., about instantly, in real-time) that can affect the ongoingwellbore servicing operation. In some aspects, the computing device canbe interfaced or networked with a spectrometer (e.g., colorimeter,portable colorimeter, UV-VIS spectrometer, portable UV-VISspectrometer). In an aspect, the amount of shale inhibitor and/or saltpresent in a WSF can be tested on-the-fly during a wellbore servicingoperation, and the WSF can be supplemented in real-time such that thewellbore servicing operation does not have to be halted, and thus costlyunproductive time can be avoided or minimized.

As will be appreciated by one of skill in the art, and with the help ofthis disclosure, employing visual detection and/or spectroscopicdetection with a portable spectrometer (e.g., portable colorimeterand/or portable UV-VIS spectrometer) of the absorption intensity for thedetection solution can generally result in obtaining data regarding theamount of shale inhibitor and/or salt in the WSF in real-time (asopposed to introducing a delay which may be significant by sending a WSFsample to be analyzed in a laboratory setting).

In an aspect, the effective supplemental amount (e.g., of shaleinhibitor, salt, base fluid, etc.) can be determined in real-time;wherein the WSF having the target amount of the shale inhibitor and/orthe salt, respectively, can be prepared in real-time, by adding theeffective supplemental amount (e.g., of supplemental shale inhibitor,salt, base fluid, etc.) to the WSF; and wherein the WSF having thetarget amount of the shale inhibitor and/or the salt, respectively, maybe placed in the wellbore and/or subterranean formation where it mayfunction as intended (e.g., prevent and/or reduce water uptake bywater-reactive formations).

In an aspect, a method of servicing a wellbore in a subterraneanformation can include (a) preparing a drilling fluid (e.g., including abase fluid, shale inhibitor, and/or a salt, wherein the shale inhibitorand/or the salt is present in the drilling fluid in a target amount(e.g., greater than or equal to 0)); (b) circulating the drilling fluidin the wellbore and/or subterranean formation to yield a circulateddrilling fluid; (c) subjecting at least a portion of the circulateddrilling fluid to solids removal to yield a substantially solids-freecirculated drilling fluid; (d) contacting an aliquot of the solids-freecirculated drilling fluid with a detector compound to form a detectionsolution; wherein the detection solution is characterized by at leastone absorption peak wavelength (λ_(max)) in the range of from about 380nm to about 760 nm; (e) detecting an absorption intensity for thedetection solution at a wavelength within about ±20% of the at least oneabsorption peak wavelength; (f) comparing the absorption intensity ofthe detection solution at the wavelength within about ±20% of the atleast one absorption peak wavelength with a target absorption intensityof the shale inhibitor and/or the salt to determine the amount of shaleinhibitor and/or salt in the circulated drilling fluid; (g) comparingthe amount of shale inhibitor and/or salt in the circulated drillingfluid with the target amount of the shale inhibitor and/or salt, whereinthe amount of shale inhibitor and/or salt in the circulated drillingfluid varies by equal to or greater than a threshold amount from thetarget amount of the shale inhibitor and/or salt; (h) responsive to (g),determining an amount of supplemental shale inhibitor and/or salteffective to provide for the circulated drilling fluid having the targetamount of the shale inhibitor and/or salt, and contacting the circulateddrilling fluid with the effective amount of supplemental shale inhibitorand/or salt on-the-fly; and (i) recycling at least a portion of thecirculated drilling fluid to the wellbore and/or subterranean formation.In such aspect, the absorption intensity for the detection solution canbe detected visually (e.g., visual detection) and/or with aspectrometer, such as a colorimeter, portable colorimeter, UV-VISspectrometer, portable UV-VIS spectrometer, etc. (e.g., spectroscopicdetection).

In an aspect, a method of servicing a wellbore in a subterraneanformation can include (a) preparing a drilling fluid including a basefluid, shale inhibitor, and/or a salt, wherein the shale inhibitorand/or the salt is present in the drilling fluid in a target amount(e.g., a target amount of greater than or equal to zero); (b)circulating the drilling fluid in the wellbore and/or subterraneanformation to yield a circulated drilling fluid; (c) subjecting at leasta portion of the circulated drilling fluid to solids removal to yield asubstantially solids-free circulated drilling fluid; (d) contacting analiquot of the solids-free circulated drilling fluid with a detector toform a detection solution; wherein the detection solution ischaracterized by a first absorption peak wavelength (first λ_(max)) (nm)and optionally by a second absorption peak wavelength (second λ_(max));and wherein the detector is contacted with the aliquot of thesolids-free circulated drilling fluid in an amount of from about 1mmol/liter to about 50 mmol/liter detector, based on the total volume ofthe detection solution; (e) detecting an absorption intensity for thedetection solution at a wavelength within about ±20% of the firstabsorption peak wavelength and optionally the second absorption peakwavelength; (f) comparing the absorption intensity of the detectionsolution at the wavelength within about ±20% of the first absorptionpeak wavelength and optionally the second absorption peak wavelengthwith a target absorption intensity at the wavelength within about ±20%of the first absorption peak wavelength and optionally the secondabsorption peak wavelength, respectively of the shale inhibitor and/orthe salt to determine the amount of shale inhibitor and/or salt in thecirculated drilling fluid; (g) comparing the amount of shale inhibitorand/or salt in the circulated drilling fluid with the target amount ofthe shale inhibitor and/or the salt, wherein the amount of shaleinhibitor and/or salt in the circulated drilling fluid varies by equalto or greater than a threshold amount from the target amount of theshale inhibitor and/or the salt; (h) responsive to (g), determining asupplemental amount of shale inhibitor, salt, and/or base fluideffective to provide for the circulated drilling fluid having the targetamount of the shale inhibitor and/or the salt, and contacting thecirculated drilling fluid with the effective supplemental amount of theshale inhibitor, the salt, and/or the base fluid in real-time; and (i)recycling at least a portion of the circulated drilling fluid to thewellbore and/or subterranean formation. In such aspect, the absorptionintensity for the detection solution can be detected visually (e.g.,visual detection) and/or with a spectrometer, such as a colorimeter,portable colorimeter, UV-VIS spectrometer, portable UV-VIS spectrometer,etc. (e.g., spectroscopic detection). In aspects where the absorptionintensity for the detection solution is detected visually, the color ofthe detection solution can be purple, blue, or another color. In aspectswhere the absorption intensity for the detection solution is detectedspectroscopically, the detection solution can be subjected toultraviolet-visible (UV-VIS) spectroscopy and/or colorimetry in aportable UV-VIS spectrometer and/or a portable colorimeter,respectively.

In an aspect, the method of servicing a wellbore in a subterraneanformation including detecting a shale inhibitor and/or a salt in a WSFas disclosed herein may display advantages when compared withconventional methods of servicing a wellbore in a subterraneanformation. The method of detecting a shale inhibitor and/or a salt in aWSF as disclosed herein may advantageously provide for acquiringreal-time data regarding the inhibitory properties of a WSF (e.g., adrilling fluid) with respect to shale formations; which in turn canresult in real-time feedback that can allow for correcting the amount ofshale inhibitor and/or salt in the WSF. Having the ability to adjust inreal-time the amount of shale inhibitor and/or salt in the WSF canadvantageously reduce the incidence of non-productive time.

In an aspect, the method of detecting a shale inhibitor and/or a salt ina WSF as disclosed herein may advantageously provide for effectivelypreventing and/or reducing water uptake by water-reactive formations,which in turn can decrease the risk and/or incidence of adverse events,such as viscosity build-up, bit balling, wellbore caving, wellboreballooning, subterranean formation integrity loss, collapse ofsubterranean formation, etc.

In an aspect, the method of detecting a shale inhibitor and/or a salt ina WSF as disclosed herein may advantageously provide for a more costeffective wellbore servicing operation. As will be appreciated by one ofskill in the art, and with the help of this disclosure, adding a shaleinhibitor and/or a salt to a WSF increases the cost. The ability toaccurately determine the concentration of shale inhibitor and/or salt inthe WSF could advantageously prevent undue additions of shale inhibitorand/or salt to the WSF, thereby lowering the cost. Additional advantagesof the method of servicing a wellbore in a subterranean formationincluding detecting a shale inhibitor and/or salt in a WSF as disclosedherein may be apparent to one of skill in the art viewing thisdisclosure.

EXAMPLES

The embodiments having been generally described, the following examplesare given as particular embodiments of the disclosure and to demonstratethe practice and advantages thereof. It is understood that the examplesare given by way of illustration and are not intended to limit thespecification or the claims in any manner.

Example 1

FIG. 1 is a flow chart showing a representative method I for measuring asalt content in a wellbore servicing fluid according to this disclosure.Upon initiating the method I at start 10, method I includes determininga wellbore servicing fluid (e.g., a drilling fluid) water salinity at20. As noted hereinabove, the wellbore servicing fluid can be a drillingfluid (e.g., a drilling mud). The drilling fluid can be a water basedmud (WBM) or an oil based mud (OBM). The water phase salinity of thewellbore servicing fluid can be determined at step 20 via any availablemethods, such as, without limitation, conductivity, colorimetry, or thelike. As step 30, a known volume of the wellbore servicing fluid (e.g.,a test sample) is dosed into a container. The known volume of thewellbore servicing fluid can be obtained subsequent circulation of thewellbore servicing fluid downhole (e.g., subsequent passage of adrilling fluid into a drill string in a wellbore, through a drill bit,and back to a surface of the wellbore via an annulus). For example, theknown volume of the wellbore servicing fluid can be obtained from a flowline or in a mud pit located at the surface proximate a drilling rig.

As detailed hereinabove, the known volume can include a test sample ofthe wellbore servicing fluid “as is”, or solids can be removed from theknown volume of the wellbore servicing fluid and/or the known volume ofthe wellbore servicing fluid can be diluted to provide the test sample.For example, as indicated at step 40, method I can further includeadding a known amount of diluent (e.g., water) to the known volume ofwellbore servicing fluid and optionally mixing to provide the testsample. Without intending to be limited by theory, diluting the knownvolume may aid in dispersing and/or separating any solids remaining inthe known volume of the wellbore servicing fluid to aid in obtaining asubstantially solids-free test sample. For example, step 40 can includecentrifuging the known volume of wellbore servicing fluid to form asolids/bottom layer and an upper/supernatant liquid layer, taking anamount from the supernatant (e.g., the water phase of the WSF), anddiluting the amount of supernatant with water (optionally with mixing)to provide the test sample. Method I includes at step 50, adding adetector compound such as a chromophore dye to the test sample andmixing. Method I further includes at step 60A, measuring the saltcontent of the test sample utilizing the colorimetric method detailedherein. Method I further includes, at step 70, reporting the data fromstep 60A to a computer control system. At step 80A, method I includes,determining (e.g., via the control system) a wellbore servicing fluid(e.g., drilling fluid) treatment based on water phase salinity (WPS) andoptionally other shale inhibitors. Method I includes, at step 90A,subjecting the wellbore servicing fluid of the wellbore servicing systemto the treatment, for example by adding salt or water to the wellboreservicing fluid system (e.g., to the mud pit). At step 100, method I caninclude waiting for a next time interval to test the wellbore servicingfluid system (e.g., the mud system). The waiting time at step 100 candepend, for example and without limitation, on the wellbore servicingfluid system volume (e.g., the mud system volume) and pump rate. At 110,the method includes initiating the method again by returning to start10.

Example 2

FIG. 2 is a flow chart showing a representative method II for measuringa shale inhibitor content in a wellbore servicing fluid according tothis disclosure. Upon initiating the method II at start 10, method IIincludes determining a wellbore servicing fluid (e.g., a drilling fluid)water salinity at 20 and dosing a known volume of the wellbore servicingfluid into a container. As noted hereinabove, the wellbore servicingfluid can be a drilling fluid (e.g., a drilling mud). The drilling fluidcan be a water based mud (WBM) or an oil based mud (OBM). The waterphase salinity of the wellbore servicing fluid can be determined at step20 via any available methods, such as, without limitation, conductivity,colorimetry, or the like. As noted hereinabove, the known volume of thewellbore servicing fluid dosed at step 30 can be obtained subsequentcirculation of the wellbore servicing fluid downhole (e.g., subsequentpassage of a drilling fluid into a drill string in a wellbore, through adrill bit, and back to a surface of the wellbore via an annulus). Forexample, the known volume of the wellbore servicing fluid can beobtained from a flow line or in a mud pit uphole. As detailedhereinabove with reference to FIG. 1, the known volume can include atest sample “as is”, or solids can be removed from the known volume ofthe wellbore servicing fluid and/or the known volume of the wellboreservicing fluid can be diluted to provide a test sample. For example, asindicated at step 40, method II can further include adding a knownamount of diluent (e.g., water) to the known volume of wellboreservicing fluid and optionally mixing to provide the test sample. Step40 can include, for example, centrifuging the known volume of wellboreservicing fluid, taking an amount from the supernatant (e.g., the waterphase of the WSF), and diluting with water (with optional mixing) toprovide the test sample. Method II includes at step 50, adding adetector compound such as a chromophore dye to the test sample andmixing. Method II further includes at step 60B, measuring the shaleinhibitor content of the test sample utilizing the colorimetric methoddetailed herein. Method II further includes, at step 70, reporting thedata from step 60B to a computer control system. At step 80B, method IIincludes, determining (e.g., via the control system) wellbore servicingfluid (e.g., drilling fluid) treatment based on the colorimetric resultsfrom step 60B and water phase salinity (WPS) from step 20. Method IIincludes, at step 90B, subjecting the wellbore servicing fluid of thewellbore servicing system to the treatment, for example by adding shaleinhibitor(s) and/or salt(s) to the wellbore servicing fluid system(e.g., to the mud pit). At step 100, method II includes waiting for anext time interval to test the wellbore servicing fluid system (e.g.,the mud system). The waiting time at step 100 can depend, for exampleand without limitation, on the wellbore servicing fluid system volume(e.g., the mud system volume) and pump rate. At 110, the method IIincludes initiating the method again by returning to start 10. Steps 10,20, 30, 40, 50, 70, 100, and 110 can be substantially the same formethod II as for method I of FIG. 1.

ADDITIONAL DISCLOSURE

A first aspect, which is a method of detecting a shale inhibitor and/ora salt in a wellbore servicing fluid (WSF) comprising: (a) contacting analiquot of the WSF with a detector compound to form a detectionsolution; wherein the detection solution is characterized by at leastone absorption peak wavelength, for example in the range of from about380 nanometers (nm) to about 760 nm; (b) detecting an absorptionintensity for the detection solution at a wavelength within about ±20%of the at least one absorption peak wavelength; (c) comparing theabsorption intensity of the detection solution at the wavelength withinabout ±20% of the at least one absorption peak wavelength with a targetabsorption intensity of the shale inhibitor and/or the salt to determinethe amount of shale inhibitor and/or salt in the WSF; and (d) comparingthe amount of shale inhibitor and/or salt in the WSF with a targetamount of the shale inhibitor and/or the salt.

A second aspect, which is the method of the first aspect, wherein thedetection solution is characterized by a visible color.

A third aspect, which is the method of the second aspect, wherein thealiquot of the WSF is further characterized by a visible color, andwherein the visible color and/or color intensity of the detectionsolution is different from the visible color and/or color intensity ofthe aliquot of the WSF.

A fourth aspect, which is the method of any one of the first through thethird aspects, wherein (b) detecting an absorption intensity for thedetection solution at a wavelength within about ±20% of the at least oneabsorption peak wavelength further comprises subjecting at least aportion of the detection solution to ultraviolet-visible (UV-VIS)spectroscopy and/or colorimetry to yield the absorption intensity of thedetection solution at the wavelength within about ±20% of the at leastone absorption peak wavelength.

A fifth aspect, which is the method of the fourth aspect, wherein atleast a portion of the detection solution is analyzed in a portableUV-VIS spectrometer and/or a portable colorimeter.

A sixth aspect, which is the method of any one of the first through thefifth aspects, wherein (c) comparing the absorption intensity of thedetection solution at the wavelength within about ±20% of the at leastone absorption peak wavelength with a target absorption intensity of theshale inhibitor and/or the salt comprises optically comparing the colorand/or color intensity of the detection solution with a target colorand/or color intensity, respectively.

A seventh aspect, which is the method of the sixth aspect, whereindetermining the amount of shale inhibitor and/or salt in the WSF furthercomprises using a calibration curve that correlates absorption intensityat the wavelength within about ±20% of the at least one absorption peakwavelength with the amount of the shale inhibitor and/or the salt,respectively.

An eighth aspect, which is the method of any one of the first throughthe seventh aspects, wherein determining the amount of shale inhibitorand/or salt in the WSF further comprises visually comparing a visuallyobserved color and/or color intensity of the detection solution with areference color chart that correlates color and/or color intensity,respectively, with the amount of the shale inhibitor and/or the salt,respectively.

A ninth aspect, which is the method of any one of the first through theeighth aspects, wherein the amount of shale inhibitor and/or salt in theWSF varies by less than a threshold amount from the target amount of theshale inhibitor and/or the salt, respectively, and wherein at least aportion of the WSF is placed in a wellbore and/or subterraneanformation.

A tenth aspect, which is the method of the ninth aspect, wherein the WSFis placed in a wellbore and/or subterranean formation prior todetermining the amount of shale inhibitor and/or salt in the WSF.

An eleventh aspect, which is the method of any one of the first throughthe ninth aspects, wherein the WSF is placed in a wellbore and/orsubterranean formation subsequent to determining the amount of shaleinhibitor and/or salt in the WSF.

A twelfth aspect, which is the method of any one of the first throughthe eighth aspects, wherein the amount of shale inhibitor and/or salt inthe WSF varies by equal to or greater than a threshold amount from thetarget amount of the shale inhibitor and/or the salt, and wherein theWSF is contacted with an effective supplemental amount of shaleinhibitor, salt, and/or base fluid to provide for the WSF having thetarget amount of the shale inhibitor and/or the salt.

A thirteenth aspect, which is the method of the twelfth aspect furthercomprising determining the effective supplemental amount and preparingthe WSF having the target amount of the shale inhibitor and/or the salton-the-fly.

A fourteenth aspect, which is the method of any one of the twelfth andthe thirteenth aspects further comprising placing at least a portion ofthe WSF having the target amount of the shale and/or the salt inhibitorin a wellbore and/or subterranean formation.

A fifteenth aspect, which is the method of any one of the first throughthe fourteenth aspects, wherein the WSF is recovered from a wellboreand/or subterranean formation, wherein at least a portion of therecovered WSF is subjected to a solids removal procedure to yield asubstantially solids-free WSF, and wherein an aliquot of thesubstantially solids-free WSF is contacted with a detector compound toform the detection solution in (a).

A sixteenth aspect, which is the method of the fifteenth aspect, whereinthe solids removal procedure is selected from the group consisting offiltration, sedimentation, decantation, centrifugation, screening,chemical dissolution, combinations thereof

A seventeenth aspect, which is the method of any one of the firstthrough the sixteenth aspects further comprising heating the detectionsolution prior to (b) detecting an absorption intensity for thedetection solution at a wavelength within about ±20% of the at least oneabsorption peak wavelength.

An eighteenth aspect, which is the method of any one of the firstthrough the seventeenth aspects, wherein the detector compound comprisesmethylene blue, ninhydrin, indane-1,2,3-trione, hydrantin, quinhydrone,Dragendorff reagent, chloranil, N-halosuccinimide, N-bromosuccinimide,N-iodosuccinimide, a hydrazo compound, a diazonium salt, fluorescein,fluorescein halide, fluorescein chloride, or combinations thereof;additionally or alternatively, the detector compound may be achromophore.

A nineteenth aspect, which is the method of any one of the first throughthe eighteenth aspects, wherein the shale inhibitor comprises a salt, apolymer, a charged polymer, a primary amine functional group, aprotonated primary amine functional group, a secondary amine functionalgroup, a protonated secondary amine functional group, a tertiary aminefunctional group, a protonated tertiary amine functional group, or acombination thereof.

A twentieth aspect, which is the method of any one of the first throughthe nineteenth aspects, wherein the WSF comprises a drilling fluid.

A twenty-first aspect, which is a method of servicing a wellbore in asubterranean formation comprising (a) preparing a drilling fluidcomprising a base fluid. a shale inhibitor, and/or a salt, wherein theshale inhibitor and/or the salt are present in the drilling fluid in atarget amount, which is greater than or equal to zero; (b) circulatingthe drilling fluid in the wellbore and/or subterranean formation toyield a circulated drilling fluid; (c) subjecting at least a portion ofthe circulated drilling fluid to solids removal to yield a substantiallysolids-free circulated drilling fluid; (d) contacting an aliquot of thesolids-free circulated drilling fluid with a detector compound to form adetection solution; wherein the detection solution is characterized byat least one absorption peak wavelength in the range of from about 380nanometers (nm) to about 760 nm; (e) detecting an absorption intensityfor the detection solution at a wavelength within about ±20% of the atleast one absorption peak wavelength; (f) comparing the absorptionintensity of the detection solution at the wavelength within about ±20%of the at least one absorption peak wavelength with a target absorptionintensity of the shale inhibitor and/or the salt to determine the amountof shale inhibitor and/or the salt, respectively, in the circulateddrilling fluid; and (g) comparing the amount of shale inhibitor and/orsalt in the circulated drilling fluid with the target amount of theshale inhibitor and/or the salt, respectively.

A twenty-second aspect, which is the method of the twenty-first aspect,wherein the detection solution is characterized by a visible color.

A twenty-third aspect, which is the method of the twenty-second aspect,wherein the aliquot of the WSF is further characterized by a visiblecolor, and wherein the visible color and/or color intensity of thedetection solution is different from the visible color and/or colorintensity of the aliquot of the WSF.

A twenty-fourth aspect, which is the method of any one of thetwenty-first through the twenty-third aspects, wherein the amount ofshale inhibitor and/or salt in the circulated drilling fluid varies byless than a threshold amount from the target amount of the shaleinhibitor and/or the salt, respectively; and wherein at least a portionof the circulated drilling fluid is recycled to the wellbore and/orsubterranean formation.

A twenty-fifth aspect, which is the method of any one of thetwenty-first through the twenty-third aspects, wherein the amount ofshale inhibitor and/or salt in the circulated drilling fluid varies byequal to or greater than a threshold amount from the target amount ofthe shale inhibitor and/or the salt, respectively; wherein thecirculated drilling fluid is contacted with an effective supplementalamount of shale inhibitor, salt, and/or base fluid to provide for thecirculated drilling fluid having the target amount of the shaleinhibitor and/or the salt; and wherein at least a portion of thecirculated drilling fluid is recycled to the wellbore and/orsubterranean formation.

A twenty-sixth aspect, which is the method of the twenty-fifth aspectfurther comprising determining the effective supplemental amount ofshale inhibitor, salt, and/or base fluid in real-time and preparing thecirculated drilling fluid having the target amount of the shaleinhibitor and/or the salt, respectively, on-the-fly.

A twenty-seventh aspect, which is a method of servicing a wellbore in asubterranean formation comprising (a) preparing a drilling fluidcomprising a base fluid, a shale inhibitor, and/or a salt, wherein theshale inhibitor and/or the salt are present in the drilling fluid in atarget amount; (b) circulating the drilling fluid in the wellbore and/orsubterranean formation to yield a circulated drilling fluid; (c)subjecting at least a portion of the circulated drilling fluid to solidsremoval to yield a substantially solids-free circulated drilling fluid;(d) contacting an aliquot of the solids-free circulated drilling fluidwith a detector compound to form a detection solution; wherein thedetection solution is characterized by a first absorption peakwavelength and optionally by a second absorption peak wavelength; andwherein the detector compound is optionally contacted with the aliquotof the solids-free circulated drilling fluid in an amount of from about0.01 mmol/liter to about 200 mmol/liter detector compound, based on thetotal volume of the detection solution; (e) detecting an absorptionintensity for the detection solution at a wavelength within about ±20%of the first absorption peak wavelength and optionally the secondabsorption peak wavelength; (f) comparing the absorption intensity ofthe detection solution at the wavelength within about ±20% of the firstabsorption peak wavelength and optionally the second absorption peakwavelength with a target absorption intensity at the wavelength withinabout ±20% of the first absorption peak wavelength and optionally thesecond absorption peak wavelength, respectively, of the shale inhibitorand/or the salt to determine the amount of shale inhibitor and/or saltin the circulated drilling fluid; and (g) comparing the amount of shaleinhibitor and/or salt in the circulated drilling fluid with the targetamount of the shale inhibitor and/or the salt, respectively.

A twenty-eighth aspect, which is the method of the twenty-seventhaspect, wherein the detection solution is characterized by a visiblecolor.

A twenty-ninth aspect, which is the method of the twenty-eighth aspect,wherein the aliquot of the WSF is further characterized by a visiblecolor, and wherein the visible color and/or color intensity of thedetection solution is different from the visible color and/or colorintensity of the aliquot of the WSF.

A thirtieth aspect, which is the method of any one of the twenty-sevenththrough the twenty-ninth aspects, wherein (f) comparing the absorptionintensity of the detection solution at the wavelength within about ±20%of the first absorption peak wavelength and optionally the secondabsorption peak wavelength with a target absorption intensity of theshale inhibitor and/or the salt comprises optically comparing the colorand/or color intensity of the detection solution with a target colorand/or color intensity, respectively.

A thirty-first aspect, which is the method of any one of thetwenty-seventh through the thirtieth aspects, wherein (f) comparing theabsorption intensity of the detection solution at the wavelength withinabout ±20% of the first absorption peak wavelength and optionally thesecond absorption peak wavelength with a target absorption intensity ofthe shale inhibitor and/or the salt further comprises subjecting atleast a portion of the detection solution to ultraviolet-visible(UV-VIS) spectroscopy and/or colorimetry in a portable UV-VISspectrometer and/or a portable colorimeter, respectively, to yield theabsorption intensity of the detection solution at the wavelength withinabout ±20% of the first absorption peak wavelength and optionally thesecond absorption peak wavelength.

A thirty-second aspect, which is the method of any one of thetwenty-seventh through the thirty-first aspects, wherein the amount ofshale inhibitor and/or salt in the circulated drilling fluid varies byequal to or greater than a threshold amount from the target amount ofthe shale inhibitor and/or the salt, respectively; wherein thecirculated drilling fluid is contacted with an effective supplementalamount of shale inhibitor, salt, and/or base fluid to provide for thecirculated drilling fluid having the target amount of the shaleinhibitor and/or the salt; and wherein at least a portion of thecirculated drilling fluid is recycled to the wellbore and/orsubterranean formation.

A thirty-third aspect, which is the method of the thirty-second aspectfurther comprising determining the effective supplemental amount ofshale inhibitor, salt, and/or base fluid and preparing the circulateddrilling fluid having the target amount of the shale inhibitor and/orthe salt, respectively, in real-time.

While embodiments of the invention have been shown and described,modifications thereof can be made by one skilled in the art withoutdeparting from the spirit and teachings of the invention. Theembodiments described herein are exemplary only, and are not intended tobe limiting. Many variations and modifications of the inventiondisclosed herein are possible and are within the scope of the invention.Where numerical ranges or limitations are expressly stated, such expressranges or limitations should be understood to include iterative rangesor limitations of like magnitude falling within the expressly statedranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4,etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example,whenever a numerical range with a lower limit, R_(L), and an upperlimit, R_(U), is disclosed, any number falling within the range isspecifically disclosed. In particular, the following numbers within therange are specifically disclosed: R=R_(L)+k*(R_(U)−R_(L)), wherein k isa variable ranging from 1 percent to 100 percent with a 1 percentincrement, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5percent, . . . , 50 percent, 51 percent, 52 percent, . . . , 95 percent,96 percent, 97 percent, 98 percent, 99 percent, or 100 percent.Moreover, any numerical range defined by two R numbers as defined in theabove is also specifically disclosed. Use of the term “optionally” withrespect to any element of a claim is intended to mean that the subjectelement is required, or alternatively, is not required. Bothalternatives are intended to be within the scope of the claim. Use ofbroader terms such as comprises, includes, having, etc. should beunderstood to provide support for narrower terms such as consisting of,consisting essentially of, comprised substantially of, etc.

For purposes of the disclosure herein, the term “comprising” includes“consisting” or “consisting essentially of.” Further, for purposes ofthe disclosure herein, the term “including” includes “comprising,”“consisting,” or “consisting essentially of.”

Accordingly, the scope of protection is not limited by the descriptionset out above but is only limited by the claims which follow, that scopeincluding all equivalents of the subject matter of the claims. Each andevery claim is incorporated into the specification as an embodiment ofthe present invention. Thus, the claims are a further description andare an addition to the embodiments of the present invention. Thediscussion of a reference in the Description of Related Art is not anadmission that it is prior art to the present invention, especially anyreference that may have a publication date after the priority date ofthis application. The disclosures of all patents, patent applications,and publications cited herein are hereby incorporated by reference, tothe extent that they provide exemplary, procedural or other detailssupplementary to those set forth herein.

What is claimed is:
 1. A method of detecting a salt content of awellbore servicing fluid (WSF) of a wellbore servicing fluid system asdescribed herein, the method comprising: (a) determining a watersalinity of a wellbore servicing fluid; (b) dosing an aliquot of thewellbore servicing fluid into a container; (c) combining the aliquot ofthe wellbore servicing fluid with a detector compound specific to thesalt and mixing to provide a detection solution in the container,wherein the detection solution is characterized by at least oneabsorption peak wavelength in the range of from about 380 nanometers(nm) to about 760 nm; (d) measuring the salt content of the detectionsolution using colorimetry by detecting an absorption intensity for thedetection solution at a wavelength within about ±20% of the at least oneabsorption peak wavelength, comparing the absorption intensity of thedetection solution at the wavelength within about ±20% of the at leastone absorption peak wavelength with a target absorption intensity todetermine the amount of salt in the WSF, and comparing the amount ofsalt in the WSF with a target amount of the salt; (e) reporting the datafrom the measuring at (d) to a computer control system; (f) determininga wellbore servicing fluid treatment based on the salt content and/or acontent of shale inhibitors; and (g) subjecting the wellbore servicingfluid of the wellbore servicing fluid system to the treatment.
 2. Themethod of claim 1 further comprising: adding a known volume of diluentand mixing prior to (c); and/or (h) waiting for a waiting time to retestthe wellbore servicing fluid system; and (i) repeating steps (a) through(g) after the waiting time.
 3. The method of claim 1, wherein thewellbore servicing fluid comprises a drilling fluid.
 4. The method ofclaim 3, wherein the drilling fluid has been recovered from circulationdownhole.
 5. The method of claim 3, wherein the wellbore servicing fluidcomprises a water based mud (WBM).
 6. The method of claim 3, wherein thewellbore servicing fluid comprises an oil based mud (OBM), and whereindosing at (b) further comprises separating an aqueous phase from an oilphase, and wherein the aliquot comprises at least a portion of theseparated aqueous phase.
 7. The method of claim 1, wherein (d) measuringthe salt content using colorimetry at (e) comprises utilizing ananalyzer comprising photosensitive dye(s) comprising the chromophorespecific to the salt.
 8. The method of claim 1, wherein the saltcomprises NaCl, KCl, NaBr, CaCl₂, CaBr₂, MgCl₂, MgBr₂, ZnBr₂, an acetatesalt, sodium acetate, potassium acetate, ammonium chloride (NH₄Cl),potassium phosphate, sodium formate, potassium formate, cesium formate,or a combination thereof.
 9. The method of claim 8, wherein the wellboreservicing fluid comprises a brine.
 10. The method of claim 1, whereinthe aliquot of the wellbore servicing fluid comprises a solids reducedand/or diluted volume of the wellbore servicing fluid.
 11. A method ofdetecting a shale inhibitor content of a wellbore servicing fluid (WSF)of a wellbore servicing fluid system as described herein, the methodcomprising: (a) determining a water phase salinity (WPS) of a wellboreservicing fluid; (b) dosing an aliquot of the wellbore servicing fluidinto a container; (c) combining the aliquot of the wellbore servicingfluid with a detector compound specific to the shale inhibitor andmixing to provide a detection solution in the container, wherein thedetection solution is characterized by at least one absorption peakwavelength in the range of from about 380 nanometers (nm) to about 760nm; (d) measuring the shale inhibitor content of the detection solutionusing colorimetry by detecting an absorption intensity for the detectionsolution at a wavelength within about ±20% of the at least oneabsorption peak wavelength, comparing the absorption intensity of thedetection solution at the wavelength within about ±20% of the at leastone absorption peak wavelength with a target absorption intensity todetermine the amount of shale inhibitor in the WSF, and comparing theamount of shale inhibitor in the WSF with a target amount of the shaleinhibitor; (e) reporting the data from the measuring at (d) to acomputer control system; (f) determining a wellbore servicing fluidtreatment based on the water phase salinity (WPS) from (a) and thecontent of shale inhibitor from (d); and (g) subjecting the wellboreservicing fluid of the wellbore servicing fluid system to the treatment.12. The method of claim 11 further comprising: adding a known volume ofdiluent and mixing prior to (c); and/or (h) waiting for a waiting timeto retest the wellbore servicing fluid system; and (i) repeating steps(a) through (g) after the waiting time.
 13. The method of claim 11,wherein the wellbore servicing fluid comprises a drilling fluid.
 14. Themethod of claim 13, wherein the drilling fluid has been recovered fromcirculation downhole.
 15. The method of claim 13, wherein the wellboreservicing fluid comprises a water based mud (WBM).
 16. The method ofclaim 13, wherein the wellbore servicing fluid comprises an oil basedmud (OBM), and wherein dosing at (b) further comprises separating anaqueous phase from an oil phase, and wherein the aliquot comprises atleast a portion of the separated aqueous phase.
 17. The method of claim11, wherein (d) measuring the shale inhibitor content of the detectionsolution using colorimetry at (d) comprises utilizing an analyzercomprising photosensitive dye(s) comprising the chromophore specific tothe shale inhibitor.
 18. The method of claim 11, wherein the shaleinhibitor comprises a polymer, a charged polymer, a salt, or acombination thereof.
 19. The method of claim 18, wherein the shaleinhibitor comprises a high molecular weight polymer, potassium chloride,sodium chloride, or a combination thereof.
 20. The method of claim 11,wherein the aliquot of the wellbore servicing fluid comprises a solidsreduced and/or diluted volume of the wellbore servicing fluid.